Using ceramic discs to evaluate fluid loss and formation damage

To prevent kicks and possible blowout of the well, the pressure from the drilling fluid must be kept above the pore pressure of the formation. This differential pressure forces the fluid into the porous formation, which results in fluid loss. Occasionally, the pressure can also exceed the formation fracturing pressure, leading to lost circulation. In both cases, fluid migrates into the formation, and may damage it in the process. In this study, the relationship between filtration volume and formation damage has been investigated. The methodology is centered around using porous discs to measure fluid filtrate and changes in permeability and mass of the discs. Fifteen samples of drilling fluid were created with different solid, polymer and fiber content. Filtrate volume was recorded by conducting a HTHP fluid loss test with a differential pressure of 6.9 MPa (1000 psi), at 90 ℃ for 30 minutes. The discs were weighed in dry conditions at the start and end of the test procedure in order to measure mass of the invasion caused by the filtrate. Changes in permeability to both water and air was determined, which combined with invasion mass, serve as indicators of formation damage. The results show how the different additives may improve the sealing capabilities and reduce filtrate volume, but that it does not necessarily correlate with reducing invasion and damage to the formation.To prevent kicks and possible blowout of the well, the pressure from the drilling fluid must be kept above the pore pressure of the formation. This differential pressure forces the fluid into the porous formation, which results in fluid loss. Occasionally, the pressure can also exceed the formation fracturing pressure, leading to lost circulation. In both cases, fluid migrates into the formation, and may damage it in the process. In this study, the relationship between filtration volume and formation damage has been investigated. The methodology is centered around using porous discs to measure fluid filtrate and changes in permeability and mass of the discs. Fifteen samples of drilling fluid were created with different solid, polymer and fiber content. Filtrate volume was recorded by conducting a HTHP fluid loss test with a differential pressure of 6.9 MPa (1000 psi), at 90 ℃ for 30 minutes. The discs were weighed in dry conditions at the start and end of the test procedure in order to measure mass of the invasion caused by the filtrate. Changes in permeability to both water and air was determined, which combined with invasion mass, serve as indicators of formation damage. The results show how the different additives may improve the sealing capabilities and reduce filtrate volume, but that it does not necessarily correlate with reducing invasion and damage to the formation

Drilling Fluid Additives for Wellbore Strengthening and Reservoir Protection

The objective of the research was to optimise drilling fluid additives for wellbore strengthening, preventing lost circulation and avoiding drilling fluid induced formation damage. Industry standard testing, such as HTHP fluid loss tests following API 13B, yield limited insight into important areas such as wellbore strengthening and formation damage. Therefore, new testing methodologies were developed and evaluated. These provided new insight into important areas for designing and evaluating drilling fluids and drilling fluid additives for wellbore strengthening and reservoir protection. Key conclusions were that exposing particles to mechanical wear significantly impacted the relative performance of materials used for preventative treatments. Oil-based fluids were found to create a high-degree of internal formation plugging, whereas water-based fluids more predominantly isolated the wellbore pressure from the pore-pressure though an external filter-cake. Inclusion of cellulose based fibres where the D90 value value ⪞ 3/2 the median pore size was shown to reduce internal plugging and reduce formation damage, in both water-based fluids and oil-based fluids. Particle degradation studies showed that CaCO3 degraded rapidly for particles > 23 μm and that the most wear resistant particles were selected cellulose-based materials. Combinations of fine CaCO3 and slightly coarser cellulose mixtures were found to be effective for creating low-permeability filter-cakes and preventing formation damage. For preventative treatment in drilling conditions with large differences between the matrix pore-size and the aperture of natural or induced fractures, a dual mode particle size distribution was found to be effective in both laboratory studies and field applications. In such situations, the fine mode of the PSD provided low filter-cake permeabilities when the particles followed an Andreasen distribution with a packing factor of around 0.08-0.10. Natural and induced fractures were most effectively sealed when granular cellulose particles made up the coarse mode of the PSD and these particles were sized similar to or slightly larger than the fracture aperture